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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q (Mark One) [X]
    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended June 30, 2004
 OR [   ]
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from ......... to ..........
 Commission File Number 1-7584
 TRANSCONTINENTAL GAS PIPE LINE CORPORATION (Exact name of registrant as specified in its charter)
 Delaware
    
    74-1079400(State or other jurisdiction of
    
    (I.R.S. Employerincorporation or organization)
    
    Identification No.)2800 Post Oak BoulevardP. O. Box 1396Houston, Texas
    
    77251(Address of principal executive offices)
    
    (Zip Code)
 Registrants telephone number, including area code (713) 215-2000 None
(Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or15(d)of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [   ] Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes
[   ] No
[ü] The number of shares of Common Stock, par value $1.00 per share, outstanding as
of June 30, 2004 was 100. REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND
(b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED
DISCLOSURE FORMAT.




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX PagePART I. FINANCIAL INFORMATION:Item 1. Financial Statements -Condensed Consolidated Statement of Income for the three and six months ended June 30, 2004 and 2003
    
    
    2Condensed Consolidated Balance Sheet as of June 30, 2004 and December 31, 2003
    
    
    3Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2004 and 2003
    
    
    5Notes to Condensed Consolidated Financial Statements
    
    
    6Item 2. Managements Narrative Analysis of the Results of Operations
    
    
    15Item 4. Controls and Procedures
    
    
    21PART II. OTHER INFORMATION
    
    
    23Item 1. Legal Proceedings
    
    
    23Item 6. Exhibits and Reports on Form 8-K
    
    
    23Certification of Principal Executive Officer - Section 302Certification of Principal Financial Officer - Section 302Certifications - Section 906
  Certain matters discussed in this report, excluding historical
information, include forward-looking statements  statements that discuss our
expected future results based on current and pending business operations. We
make these forward-looking statements in reliance on the safe harbor
protections provided under the Private Securities Litigation Reform Act of
1995. Forward-looking statements can be identified by words such as
anticipates, believes, expects, planned, scheduled, could,
continues, estimates, forecasts, might, potential, projects or
similar expressions. Although we believe these forward-looking statements are
based on reasonable assumptions, statements made regarding future results are
subject to a number of assumptions, uncertainties and risks that may cause
future results to be materially different from the results stated or implied in
this document. Additional information about issues that could cause actual
results to differ materially from forward-looking statements is contained in
our 2003 Annual Report on Form 10-K and 2004 First Quarter Report on Form 10-Q. 1




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PART 1  FINANCIAL INFORMATION 
 ITEM 1. Financial Statements. TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED STATEMENT OF INCOME   Three Months Ended
    
    Six Months EndedJune 30,
    
    June 30,2004
    
    2003
    
    2004
    
    2003Operating Revenues:Natural gas sales
    
    $
    95,271
    
    
    $
    104,120
    
    
    $
    219,145
    
    
    $
    263,707Natural gas transportation
    
    
    192,428
    
    
    
    194,116
    
    
    
    399,354
    
    
    
    396,445Natural gas storage
    
    
    30,289
    
    
    
    31,145
    
    
    
    61,849
    
    
    
    62,966Other
    
    
    3,070
    
    
    
    10,292
    
    
    
    5,548
    
    
    
    13,830Total operating revenues
    
    
    321,058
    
    
    
    339,673
    
    
    
    685,896
    
    
    
    736,948Operating Costs and Expenses:Cost of natural gas sales
    
    
    95,271
    
    
    
    104,120
    
    
    
    217,596
    
    
    
    263,707Cost of natural gas transportation
    
    
    2,669
    
    
    
    5,938
    
    
    
    13,909
    
    
    
    10,643Operation and maintenance
    
    
    46,058
    
    
    
    46,820
    
    
    
    95,455
    
    
    
    92,149Administrative and general
    
    
    31,218
    
    

    
    26,282
    
    
    
    62,444
    
    
    
    55,034Depreciation and amortization
    
    
    49,152
    
    
    
    56,075
    
    
    
    96,621
    
    
    
    104,128Taxes - other than income taxes
    
    
    12,024
    
    
    
    9,776
    
    
    
    24,773
    
    
    
    20,631Other, net
    
    
    182
    
    
    
    (999
    )
    
    
    169
    
    
    
    (923
    )Total operating costs and expenses
    
    
    236,574
    
    
    
    248,012
    
    
    
    510,967
    
    
    
    545,369Operating Income
    
    
    84,484
    
    
    
    91,661
    
    
    
    174,929
    
    
    
    191,579Other (Income) and Other Deductions:Interest expense
    
    
    22,164
    
    
    
    22,203
    
    
    
    44,330
    
    
    
    44,345Interest income  affiliates
    
    
    (3,069
    )
    
    
    (1,206
    )
    
    
    (4,440
    )
    
    
    (3,272
    )Allowance for equity and borrowed funds used during construction (AFUDC)
    
    
    (1,827
    )
    
    
    (4,098
    )
    
    
    (3,345
    )
    
    
    (9,619
    )Equity in earnings of unconsolidated affiliates
    
    
    (1,843
    )
    
    
    (1,942
    )
    
    
    (3,519
    )
    
    
    (3,787
    )Miscellaneous other (income) deductions, net
    
    
    (1,029
    )
    
    
    (2,001
    )
    
    
    (1,774
    )
    
    
    (3,895
    )Total other (income) and other deductions
    
    
    14,396
    
    
    
    12,956
    
    
    
    31,252
    
    
    
    23,772Income before Income Taxes
    
    
    70,088
    
    
    
    78,705
    
    
    
    143,677
    
    
    
    167,807Provision for Income Taxes
    
    
    26,756
    
    
    
    30,854
    
    
    
    54,997
    
    
    
    65,023Net Income
    
    $
    43,332
    
    
    $
    47,851
    
    
    $
    88,680
    
    
    $
    102,784
 See accompanying notes. 2




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED BALANCE SHEET   June 30,
    
    December 31,2004
    
    2003ASSETSCurrent Assets:Cash
    
    $
    223
    
    
    $
    300Receivables:Affiliates
    
    
    3,808
    
    
    
    9,360Advances to affiliates
    
    
    139,425
    
    
    
    49,947Others
    
    
    101,234
    
    
    
    133,814Transportation and exchange gas receivables
    
    
    15,033
    
    
    
    22,756Inventories
    
    
    108,276
    
    
    
    110,766Deferred income taxes
    
    
    19,660
    
    
    
    20,616Other
    
    
    15,891
    
    
    
    17,095Total current assets
    
    
    403,550
    
    
    
    364,654Investments, at cost plus equity in undistributed earnings
    
    
    44,116
    
    
    
    43,665Property, Plant and Equipment:Natural gas transmission plant
    
    
    5,798,263
    
    
    
    5,758,739Less-Accumulated depreciation and amortization
    
    
    1,513,725
    
    
    
    1,439,493Total property, plant and equipment, net
    
    
    4,284,538
    
    
    
    4,319,246Other Assets
    
    
    192,834
    
    
    
    205,862Total assets
    
    $
    4,925,038
    
    
    $
    4,933,427
 See accompanying notes. 3




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited) June 30,
    
    December 31,2004
    
    2003LIABILITIES AND STOCKHOLDERS EQUITYCurrent Liabilities:Payables:Affiliates
    
    $
    42,473
    
    
    $
    64,092Other
    
    
    65,708
    
    
    
    102,600Transportation and exchange gas payables
    
    
    14,934
    
    
    
    22,149Accrued liabilities
    
    
    129,420
    
    
    
    129,531Reserve for rate refunds
    
    
    6,874
    
    
    
    10,610Current maturities of long-term debt
    
    
    199,894
    
    
    
    Total current liabilities
    
    
    459,303
    
    
    
    328,982Long-Term Debt
    
    
    924,500
    
    
    
    1,123,958Other Long-Term Liabilities:Deferred income taxes
    
    
    954,723
    
    
    
    931,940Other
    
    
    113,758
    
    
    
    114,829Total other long-term liabilities
    
    
    1,068,481
    
    
    
    1,046,769Contingent liabilities and commitments (Note 2)Common Stockholders Equity:Common stock $1.00 par value:100 shares authorized, issued and outstanding
    
    
    
    
    
    
    Premium on capital stock and other paid-in capital
    
    
    1,652,430
    
    
    
    1,652,430Retained earnings
    
    
    821,112
    
    
    
    782,432Accumulated other comprehensive loss
    
    
    (788
    )
    
    
    (1,144
    )Total common stockholders equity
    
    
    2,472,754
    
    
    
    2,433,718Total liabilities and stockholders equity
    
    $
    4,925,038
    
    
    $
    4,933,427
 See accompanying notes. 4




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS   Six Months EndedJune 30,2004
    
    2003Cash flows from operating activities:Net income
    
    $
    88,680
    
    
    $
    102,784Adjustments to reconcile net income to net cash provided
by (used in) operating activities:Depreciation and amortization
    
    
    97,550
    
    
    
    99,994Deferred income taxes
    
    
    23,484
    
    
    
    17,409Allowance for equity funds used during construction
(Equity AFUDC)
    
    
    (2,375
    )
    
    
    (6,914
    )Changes in operating assets and liabilities:Receivables
    
    
    38,132
    
    
    
    40,972Transportation and exchange gas receivables
    
    
    7,723
    
    
    
    (2,256
    )Inventories
    
    
    2,490
    
    
    
    (39,604
    )Payables
    
    
    (34,962
    )
    
    
    20,578Transportation and exchange gas payables
    
    
    (7,215
    )
    
    
    7,543Accrued liabilities
    
    
    (111
    )
    
    
    3,406Reserve for rate refunds
    
    
    (3,736
    )
    
    
    1,770Other, net
    
    
    14,961
    
    
    
    (24,175
    )Net cash provided by operating activities
    
    
    224,621
    
    
    
    221,507Cash flows from financing activities:Debt issue costs
    
    
    
    
    
    
    (121
    )Change in cash overdrafts
    
    
    (15,108
    )
    
    
    (12,139
    )Common stock dividends paid
    
    
    (50,000
    )
    
    
    (155,000
    )Advances from affiliate, net
    
    
    
    
    
    
    (3,022
    )Net cash used in financing activities
    
    
    (65,108
    )
    
    
    (170,282
    )Cash flows from investing activities:Property, plant and equipment:Additions, net of equity AFUDC
    
    
    (59,847
    )
    
    
    (111,466
    )Changes in accounts payable
    
    
    (8,441
    )
    
    
    (519
    )Advances to affiliates, net
    
    
    (89,478
    )
    
    
    52,675Other, net
    
    
    (1,824
    )
    
    
    2,203Net cash used in investing activities
    
    
    (159,590
    )
    
    
    (57,107
    )Net decrease in cash
    
    
    (77
    )
    
    
    (5,882
    )Cash at beginning of period
    
    
    300
    
    
    
    6,183Cash at end of period
    
    $
    223
    
    
    $
    301
 See accompanying notes. 5




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TRANSCONTINENTAL GAS PIPE LINE CORPORATION 
 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned
subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned
subsidiary of The Williams Companies, Inc. (Williams). In this report, Transco (which includes Transcontinental Gas Pipe Line
Corporation and unless the context otherwise requires, all of our subsidiaries)
is at times referred to in the first person as we us or our. The condensed consolidated financial statements include our accounts and
the accounts of our majority-owned subsidiaries. Companies in which we and our
subsidiaries own 20 percent to 50 percent of the voting common stock or
otherwise exercise significant influence over operating and financial policies
of the company are accounted for under the equity method. The condensed consolidated financial statements have been prepared from
our books and records. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with accounting
principles generally accepted in the United States have been condensed or
omitted. The condensed unaudited consolidated financial statements include all
adjustments both normal recurring and others which, in the opinion of our
management, are necessary to present fairly our financial position at June 30,
2004, and results of operations for the three and six months ended June 30,
2004 and 2003, and cash flows for the six months ended June 30, 2004 and 2003.
These condensed consolidated financial statements should be read in conjunction
with the consolidated financial statements and the notes thereto included in
our 2003 Annual Report on Form 10-K and 2004 First Quarter Report on Form 10-Q. As a participant in Williams cash management program, we have advances to
and from Williams. The advances are represented by demand notes. The interest
rate on intercompany demand notes is based upon the weighted average cost of
Williams debt outstanding at the end of each quarter. Prior to April 29,
2004, the advances flowed through our parent company, WGP. Through an agency agreement, Williams Power Company (WPC), an affiliate of
ours, manages all jurisdictional merchant gas sales for us, receives all
margins associated with such business and, as our agent, assumes all market and
credit risk associated with our jurisdictional merchant gas sales.
Consequently, our merchant gas sales service has no impact on our operating
income or results of operations. The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from
those estimates. Estimates and assumptions which, in the opinion of management,
are significant to the underlying amounts included in the financial statements
and for which it would be reasonably possible that future events or information
could change those estimates include: 1) revenues subject to refund; 2)
litigation-related contingencies; 3) environmental remediation obligations; 4)
impairment assessments of long-lived assets; 5) deferred and other income
taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8)
asset retirement obligations. 6




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Our Board of Directors declared a cash dividend on common stock in the
amount of $50 million on June 30, 2004. Comprehensive income for the three and six months ended June 30, 2004 and
2003 respectively, are as follows (in thousands): Three Months
    
    Six MonthsEnded June 30,
    
    Ended June 30,2004
    
    2003
    
    2004
    
    2003Net income
    
    $
    43,332
    
    
    $
    47,851
    
    
    $
    88,680
    
    
    $
    102,784Equity interest in
unrealized gain/(loss) on
interest rate hedge
    
    
    551
    
    
    
    (208
    )
    
    
    356
    
    
    
    (53
    )Total comprehensive income
    
    $
    43,883
    
    
    $
    47,643
    
    
    $
    89,036
    
    
    $
    102,731
 2. CONTINGENT LIABILITIES AND COMMITMENTS Rate and Regulatory Matters General rate case (Docket No. RP01-245)On March 1, 2001, we submitted to
the Federal Energy Regulatory Commission (FERC) a general rate filing
principally designed to recover costs associated with an increase in rate base
resulting from additional plant, an increase in rate of return and related
taxes, and an increase in operation and maintenance expenses. In July, 2002, the FERC approved a Stipulation and Agreement (Settlement)
which resolved all cost of service, throughput and throughput mix issues in
this rate case proceeding with the exception of one cost of service issue
related to the valuation of certain right-of-way access for the installation of
a fiber optic system by a then Transco affiliate, the resolution of which is to
be applied prospectively. The other issues not resolved by the Settlement
include various cost allocation, rate design and tariff matters. On December 3, 2002, an Administrative Law Judge (ALJ) issued his initial
decision on the issues not resolved by the Settlement. In the initial
decision, the ALJ determined, among other things, that (1) our existing
treatment of the arrangement with our former affiliate relating to right of way
is just and reasonable (2) our proposal to roll-in the costs of the Cherokee,
Pocono and SunBelt projects is unjust and unreasonable, and (3) our recovery of
the costs of the Mobile Bay expansion project on a rolled-in basis is unjust
and unreasonable. As to the Mobile Bay issue, the ALJ determined that we had
the burden of establishing that roll-in of that project is just and reasonable,
but did not address the issue of any potential refunds. Our current rates are
based on the roll-in of the Mobile Bay expansion project. On March 26, 2004, the FERC issued an order that affirmed, in part, and
reversed, in part, the ALJs initial decision on the issues not resolved by the
Settlement. On the issues discussed above, the FERC affirmed the ALJs
determination that our existing treatment of the arrangement with our former
affiliate relating to right of way is just and reasonable and our proposal to
roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and
unreasonable, but reversed the ALJs rejection of our proposal to recover the
costs of the Mobile Bay expansion project on a rolled-in basis and found that
we had shown that our proposed rolled-in rates are just and reasonable. The
FERC also affirmed the ALJs determination that we must separate our Emergency
Eminence Withdrawal service from our Rate Schedule FT service and offer the
Emergency Eminence Withdrawal service under a separate rate schedule, thereby
permitting shippers 7




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to decide whether to take that service. Currently, the costs of the
Emergency Eminence Withdrawal service is included as part of our Rate Schedule
FT service for those shippers that can access the Eminence Storage Field.
Under the FERCs decision, we would be at risk for those costs to the extent
that shippers did not elect to subscribe to all of the separately offered
service. Pursuant to the Settlement, this change, if upheld, would be
implemented on a prospective basis. On April 26, 2004, several parties,
including Transco, filed requests for rehearing of the FERCs March 26, 2004
order. General rate case (Docket No. RP97-71)On November 1, 1996, we submitted
to the FERC a general rate case filing principally designed to recover costs
associated with increased capital expenditures. The filing also included a pro-forma proposal to roll-in the costs of our
Leidy Line and Southern expansion incremental projects. All issues in this proceeding previously were resolved through settlement
or litigation, with the exception of the roll-in issues consolidated with
Docket No. RP95-197, which is discussed below, and one issue remanded to the
FERC by the United States Court of Appeals for the District of Columbia Circuit
(D.C. Circuit Court) relating to the rate paid by a shipper under its firm
transportation contract. The shipper had requested that the FERC reinstate its
discounted transportation rate under the firm transportation contract effective
on June 1, 2003 or as soon as possible thereafter, that we be directed to make
refunds of amounts collected from the shipper in excess of the discounted rate
since February 1, 2001, with interest, and that we be authorized to make
billing adjustments to recover the cost of the refunds from our other shippers.
On April 19, 2004, the FERC issued an order in response to the D.C. Circuit
Courts remand. The FERC affirmed its conclusion that the discounted
transportation rate is not justified, and denied the shippers request that its
discounted rate be reinstated and its request for refunds. No party filed a
request for rehearing of the FERCs April 19, 2004 order; therefore, the FERCs
decision on this matter is final. General rate case (Docket No. RP95-197)Through settlement and litigation,
all issues in this proceeding have been resolved, except a cost allocation
issue related to our implementation of the roll-in of the costs of our Leidy
Line and Southern Expansion projects. In April 1999, the FERC issued an order reversing a prior ALJ decision,
and concluded that we had demonstrated that our proposed rolled-in rate
treatment was just and reasonable. As a result, the FERC remanded to the ALJ
issues regarding the implementation of our roll-in proposal. Several parties
filed requests for rehearing of the FERCs order but their requests, as well as
subsequent court appeals, were denied. The ALJ generally ruled in favor of our implementation positions, with the
major exception that the ALJ required that the roll-in of the costs of the
incremental projects into Transcos system rates be phased in over a three-year
period. In October 2001, the FERC issued an order on the ALJs decision which
generally upheld the decision, except that the FERC reversed the ALJs decision
to phase the roll-in of the costs finding that the three-year phasing is not
necessary in this case. In August 2002, we filed to implement, among other
things, the FERCs decision on the roll-in of the costs of the incremental
Leidy Line and Southern expansion projects. On December 12, 2002, the FERC
issued an order accepting our compliance filing effective October 1, 2002. On
January 13, 2003, certain parties filed for rehearing of the FERCs December
12, 2002 order, arguing that we improperly reallocated certain storage costs in
implementing the roll-in. 8




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Gathering facilities spin-down order (Docket Nos. CP96-206-000 and
CP96-207-000)In 1996, we filed an application with the FERC for an order
authorizing the abandonment of certain facilities located onshore and offshore
in Texas, Louisiana and Mississippi by conveyance to an affiliate, Williams Gas
Processing  Gulf Coast Company (Gas Processing). The net book value of these
facilities at June 30, 2004, was approximately $347 million. Concurrently, Gas
Processing filed a petition for declaratory order requesting a determination
that its gathering services and rates be exempt from FERC regulation under the
NGA. The FERC issued an order dismissing our application and Gas Processings
petition for declaratory order and in 2001, the FERC issued an order that
denied our request for rehearing. Certain parties, including us, filed in the
D.C. Circuit Court petitions for review of the FERCs orders and in June 2003,
those petitions were denied. Several parties petitioned the United States
Supreme Court for review of the D.C. Circuit Courts opinion, and on January
12, 2004, the Court denied those petitions. While the proceedings related to the 1996 application were pending, we
filed with the FERC the applications described below seeking authorization to
abandon portions of the facilities included in the 1996 application. North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos.
CP01-32 and CP01-34)In 2000, we filed an application with the FERC seeking
authorization to abandon certain of our offshore Texas facilities by conveyance
to Gas Processing. Gas Processing filed a contemporaneous request that the FERC
declare that the facilities sought to be abandoned would be considered
nonjurisdictional gathering facilities upon transfer to Gas Processing. The
FERC approved the abandonment and the non-jurisdictional treatment of all of
these facilities. Effective December 2001, we transferred to Gas Processing the
North Padre Island facilities through a non-cash dividend of $3.3 million,
which represents the net book value of the facilities as of that date. Parties
filed petitions for review of the FERCs 2001 order to the D.C. Circuit Court
which were consolidated with the appeals of the FERCs orders in CP96-206 and
CP96-207, discussed above, and which were denied by the D.C. Circuit Court in
its opinion issued in June, 2003. In 2001, Shell Offshore, Inc. filed a
complaint at the FERC against Gas Processing, Williams Field Services Company
(WFS) and us alleging concerted actions by these affiliates frustrated the
FERCs regulation of us. The alleged actions are related to offers of gathering
service by WFS and its subsidiaries with respect to the North Padre Island
facilities. In 2002, the FERC issued an order reasserting jurisdiction over
that portion of the North Padre Island facilities previously transferred to
WFS. The FERC also determined a gathering rate for service on these
facilities, which is to be collected by us. Transco, Gas Processing and WFS
each sought rehearing of the FERCs order, and in May 2003, the FERC denied
those requests for rehearing. Transco, Gas Processing and WFS filed petitions
for review of the FERCs orders with the D.C. Circuit Court and on July 13,
2004, the court granted the petitions, vacating the FERCs orders and remanding
the case to the FERC for further proceedings not inconsistent with the courts
opinion. With regard to the approval of the spin-down of the Central Texas
facilities, a Transco customer filed a complaint with the FERC in Docket No.
RP02-309 seeking the revocation of the FERCs spin-down approval. In September
2002, the FERC issued an order requiring that, upon transfer of the Central
Texas facilities, we acquire capacity on the transferred facilities and provide
service to the existing customer under the original terms and conditions of
service. Our request for rehearing was denied in May 2003. The FERC also
required that we notify the FERC of Transcos plans with regard to the transfer
of the Central Texas facilities to Gas Processing. We replied that due to the
numerous outstanding issues affecting the transfer of those facilities, we
could not at that time predict the timing for the implementation of the
transfer of the Central Texas facilities. Transco and the customer each also
filed a request for rehearing of the FERCs May 2003 order. On May 6, 2004, the
FERC issued an order on rehearing effectively granting the customers request
for rehearing. On June 7, 2004, we filed a request for rehearing of the May 6,
2004 order, which the 9




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FERC denied on July 6, 2004. On July 14, 2004, we filed a petition for
review of the FERCs orders with the D.C. Circuit Court. At June 30, 2004, the
net book value of these facilities was $66 million including the Williams
purchase price allocation pushed down to Transco. North High Island/West Cameron Systems and Central Louisiana System
Spin-down ProceedingsIn 2001 the FERC issued orders authorizing us to spin
down only a portion of these systems to Gas Processing. All legal challenges of
these FERC orders have been exhausted and while we have not yet transferred any
of the facilities authorized for spin down to our gas processing affiliate, we
continue to evaluate the option of doing so. On May 6, 2004, the FERC issued an
order relating to the Central Louisiana system spin-down proceeding in which
the FERC required Transco and Gas Processing to show cause, due to developments
in another proceeding, why certain of the Central Louisiana facilities
previously found to be gathering should not be classified as jurisdictional
transmission facilities. We filed our response to the show cause order on July
6, 2004, arguing that the FERC should not alter its conclusion that the
facilities serve a gathering function. The net book value, at the application date, of the North High Island/West
Cameron and Central Louisiana facilities included in these two applications was
approximately $65 million including the Williams purchase price allocation
pushed down to Transco. South Texas Pipeline Facilities Abandonment ProceedingIn May 2003, the
FERC denied our request to abandon the South Texas pipeline facilities by sale
to a third party. On June 25, 2003, Transco and the third party purchaser
announced that they had agreed to terminate the purchase and sale agreement for
the facilities. On July 6, 2004, we executed another agreement to sell the
South Texas pipeline facilities to a third party, and on July 28, 2004, we
filed an application with the FERC for authorization to effectuate the sale.
The net book value of such facilities as of June 30, 2004 was approximately $30
million, including the Williams purchase price allocation pushed down to
Transco. 1999 Fuel Tracker (Docket No. TM99-6-29)On March 1, 1999, we made our
annual filing pursuant to our FERC Gas Tariff to recalculate the fuel retention
percentages applicable to our transportation and storage rate schedules, to be
effective April 1, 1999. Included in the filing were two adjustments that
increased the estimated gas required for operations in prior periods by
approximately 8 billion cubic feet. Certain parties objected to the inclusion
of those adjustments and the FERC accepted the filing to be effective April 1,
1999, subject to refund and to further FERC action. In subsequent orders, the
FERC initially disallowed most of the adjustments, but later reconsidered that
decision and allowed us to make the adjustments, with the requirement we
collect the adjustments over a seven-year period. Although several of our
customers filed for rehearing of the FERCs decision to allow us to recover the
adjustments, the FERC denied the request for rehearing, and an appeal of the
FERCs decision was filed but later dismissed. In the second quarter of 2001,
we recorded a $15 million reduction in the cost of natural gas transportation
and reduced the related interest expense by $3 million to reflect the
regulatory approval to recover the cost of gas required for operations in prior
periods. The FERC then issued orders in which it addressed our proposed method for
recovering the permitted adjustments. The FERC determined that rather than
collecting the revenue (including interest) represented by the adjustments, we
should collect only the actual volumes comprising the adjustments. In the third
quarter of 2002, as a result of the FERCs determination, we recorded $3
million of interest expense that had been previously reduced in the second
quarter of 2001. Certain customers filed requests for rehearing of the FERCs
decision, and the FERC denied those requests. Several parties have filed a
joint petition for review in the D.C. Circuit Court of the FERCs order. In
accordance with the FERCs order, on 10




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January 21, 2004 we distributed refunds and assessed surcharges to our
customers for the period April 1, 1999 through March 31, 2003. We assessed
further surcharges to our customers covering the period April 1, 2003 through
January 31, 2004 on March 10, 2004. We implemented the revised fuel retention
factors resulting from application of the FERCs order on a prospective basis
beginning February 1, 2004. OtherWilliams responded to a subpoena from the Commodities Futures
Trading Commission and inquiries from the FERC related to natural gas storage
inventory issues. Williams believes that these inquiries are a part of an
ongoing general industry-wide investigation. The inquiries relate to the formal
reporting of inventory levels, the sharing of non-public data concerning
inventory levels, and the potential uses of such data in natural gas trading.
We own and operate natural gas storage facilities. Legal Proceedings. Royalty claims and litigationIn connection with our renegotiations with
producers to resolve take-or-pay and other contract claims and to amend gas
purchase contracts, we entered into certain settlements which may require that
we indemnify producers for claims for additional royalties resulting from such
settlements. Through our agent WPC, we continue to purchase gas under contracts
which extend, in some cases, through the life of the associated gas reserves.
Certain of these contracts contain royalty indemnification provisions, which
have no carrying value. We have been made aware of demands on producers for
additional royalties and such producers may receive other demands which could
result in claims against us pursuant to royalty indemnification provisions.
Indemnification for royalties will depend on, among other things, the specific
lease provisions between the producer and the lessor and the terms of the
agreement between the producer and us. Consequently, the potential maximum
future payments under such indemnification provisions cannot be determined. As a result of these settlements, we have been sued by certain producers
seeking indemnification. We are currently a defendant in one such lawsuit.
Freeport-McMoRan, Inc., filed a lawsuit against us in the 19th Judicial
District Court in East Baton Rouge, Louisiana in which it asserted damages,
including interest calculated through June 30, 2004, of approximately $10
million. The case was tried in 2003 and resulted in a judgment favorable to
us, which Freeport-McMoRan is appealing. In 1998, the United States Department of Justice (DOJ) informed Williams
that Jack Grynberg, an individual, had filed claims in the United States
District Court for the District of Colorado under the False Claims Act against
Williams and certain of its wholly-owned subsidiaries including us. Mr.
Grynberg has also filed claims against approximately 300 other energy companies
and alleges that the defendants violated the False Claims Act in connection
with the measurement, royalty valuation and purchase of hydrocarbons. The
relief sought is an unspecified amount of royalties allegedly not paid to the
federal government, treble damages, a civil penalty, attorneys fees, and
costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui
tam cases, including the action filed against the Williams entities in the
United States District Court for the District of Colorado. In October 1999, the
Panel on Multi-District Litigation transferred all of the Grynberg qui tam
cases, including those filed against Williams, to the United States District
Court for the District of Wyoming for pre-trial purposes. In October 2002, the
court granted a motion to dismiss Grynbergs royalty valuation claims.
Grynbergs measurement claims remain pending against Williams, including us,
and the other defendants. 11




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Environmental Matters We are subject to extensive federal, state and local environmental laws
and regulations which affect our operations related to the construction and
operation of pipeline facilities. Appropriate governmental authorities enforce
these laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties, assessment and remediation requirements
and injunctions as to future compliance. Our use and disposal of hazardous
materials are subject to the requirements of the federal Toxic Substances
Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA)
and comparable state statutes. The Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA), also known as Superfund, imposes
liability, without regard to fault or the legality of the original act, for
release of a hazardous substance into the environment. Because these laws and
regulations change from time to time, practices that have been acceptable to
the industry and to the regulators have to be changed and assessment and
monitoring have to be undertaken to determine whether those practices have
damaged the environment and whether remediation is required. Since 1989, we
have had studies underway to test some of our facilities for the presence of
toxic and hazardous substances to determine to what extent, if any, remediation
may be necessary. On the basis of the findings to date, we estimate that over
the next five years environmental assessment and remediation costs under TSCA,
RCRA, CERCLA and comparable state statutes will total approximately $27 million
to $30 million, measured on an undiscounted basis. This estimate depends upon a
number of assumptions concerning the scope of remediation that will be required
at certain locations and the cost of the remedial measures. We are conducting
environmental assessments and implementing a variety of remedial measures that
may result in increases or decreases in the total estimated costs. At June 30,
2004, Transco had a balance of approximately $27 million for these estimated
costs recorded in current liabilities ($5 million) and other long-term
liabilities ($22 million) in the accompanying Condensed Consolidated Balance
Sheet. We consider prudently incurred environmental assessment and remediation
costs and costs associated with compliance with environmental standards to be
recoverable through rates. To date, we have been permitted recovery of
environmental costs, and it is our intent to continue seeking recovery of such
costs, through future rate filings. Therefore, these estimated costs of
environmental assessment and remediation have been recorded as regulatory
assets in current assets and other assets in the accompanying Condensed
Consolidated Balance Sheet. We have used lubricating oils containing polychlorinated biphenyls (PCBs)
and, although the use of such oils was discontinued in the 1970s, we have
discovered residual PCB contamination in equipment and soils at certain gas
compressor station sites. We have worked closely with the EPA and state
regulatory authorities regarding PCB issues, and we have a program to assess
and remediate such conditions where they exist, the costs of which are included
in the $27 million to $30 million range discussed above. We have been identified as a potentially responsible party (PRP) at
various Superfund and state waste disposal sites. Based on present volumetric
estimates and other factors, our estimated aggregate exposure for remediation
of these sites is less than $500,000. The estimated remediation costs for all
of these sites have been included in the environmental reserve discussed above.
Liability under CERCLA (and applicable state law) can be joint and several with
other PRPs. Although volumetric allocation is a factor in assessing liability,
it is not necessarily determinative; thus, the ultimate liability could be
substantially greater than the amounts described above. We are also subject to the federal Clean Air Act and to the federal Clean
Air Act Amendments of 1990 (1990 Amendments), which added significantly to the
existing requirements established by the federal 12




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Clean Air Act. The 1990 Amendments required that the EPA issue new
regulations, mainly related to stationary sources, air toxics, ozone
non-attainment areas and acid rain. During the last few years we have been
installing new emission control devices required for new or modified facilities
in areas designated as non-attainment by EPA. We operate some of our facilities
in areas of the country currently designated as non-attainment with the
one-hour ozone standard. In April 2004, EPA designated eight-hour ozone
non-attainment areas. We also operate facilities in areas of the country now
designated as non-attainment with the eight-hour ozone standard. Pursuant to
non-attainment area requirements of the 1990 Amendments, and proposed EPA rules
designed to mitigate the migration of ground-level ozone (NOx) in 22 eastern
states, we are planning installation of air pollution controls on existing
sources at certain facilities in order to reduce NOx emissions. We anticipate
that additional facilities may be subject to increased controls within five
years. For many of these facilities, we are developing more cost effective and
innovative compressor engine control designs. Due to the developing nature of
federal and state emission regulations, it is not possible to precisely
determine the ultimate emission control costs. In March 2004 and June 2004, the
EPA promulgated additional regulations regarding hazardous air pollutants;
these regulations may impose controls in addition to the controls described
above. The emission control additions required to comply with current federal
Clean Air Act requirements, the 1990 Amendments, the hazardous air pollutant
regulations, and the individual state implementation plans for NOx reductions
are estimated to include costs in the range of $230 million to $260 million
subsequent to 2003. EPAs recent designation of new non-attainment areas will
result in new federal and state regulatory action that may impact our
operations. As a result, the cost of additions to property, plant and equipment
is expected to increase. We are unable at this time to estimate with any
certainty the cost of additions that may be required to meet new regulations,
although it is believed that some of those costs are included in the ranges
discussed above. Management considers costs associated with compliance with the
environmental laws and regulations described above to be prudent costs incurred
in the ordinary course of business and, therefore, recoverable through our
rates. Other claimsIn September 2002, an interconnected pipeline informed us of
a proposed adjustment to the volumes delivered to us at an interconnect meter
station in Clinton Co., Pennsylvania related to the period July 2001 through
June 2002 and for September 2002. The pipeline asserted that the adjustment was
necessary because obstructions in the meter tubes affected readings at the
meter station, resulting in an understatement of the volumes delivered to us
during those periods. The pipeline initially claimed that an adjustment ranging
from approximately 263,000 dekatherms (dt) to 739,000 dt was necessary, but in
January 2003, submitted to us an adjustment of approximately 697,000 dt. In
June 2004, the pipeline agreed to an adjustment of approximately 255,000 dt to
resolve this matter. We believe that this adjustment will have no impact on our
operating income or results of operations. Safety Matters Pipeline Integrity RegulationsIn December 2003, the United States
Department of Transportation Office of Pipeline Safety issued a final rule
pursuant to the requirements of the Pipeline Safety Improvement Act of 2002
that was enacted in December 2002. The rule requires gas pipeline operators to
develop integrity management programs for transmission pipelines that could
affect high consequence areas in the event of pipeline failure, including a
baseline assessment and periodic reassessments to be completed within specified
timeframes. Currently, we estimate that the cost to perform required
assessments and repairs will be between $190 million and $215 million over the
2003 to 2012 period. Management considers the costs associated with compliance
with the proposed rule to be prudent costs incurred in the ordinary course of
business and, therefore, recoverable through our rates. 13




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Summary Litigation, arbitration, regulatory matters, environmental matters and
safety matters are subject to inherent uncertainties. Were an unfavorable
ruling to occur, there exists the possibility of a material adverse impact on
the results of operations in the period in which the ruling occurs.
Management, including internal counsel, currently believes that the ultimate
resolution of the foregoing matters, taken as a whole and after consideration
of amounts accrued, insurance coverage, recovery from customers or other
indemnification arrangements, will not have a materially adverse effect upon
our future financial position. Other Commitments Commitments for constructionWe have commitments for construction and
acquisition of property, plant and equipment of approximately $43 million at
June 30, 2004. 3. DEBT AND FINANCING ARRANGEMENTS Revolving Credit and Letter of Credit Facilities On May 3, 2004, Williams entered into a new three-year $1 billion secured
revolving credit facility (Credit Agreement) which is available for borrowings
and letters of credit. At June 30, 2004, letters of credit totaling $181
million, none of which are associated with us, have been issued by the
participating institutions under this facility and no revolving credit loans
were outstanding. Williams also has a commitment from its agent bank
to expand its credit facility by an additional $275 million. Transco and Northwest Pipeline Corporation, a subsidiary of
WGP, have access to $400 million each under the facility. The new facility is
secured by certain Williams midstream assets. Additionally, the facility is
guaranteed by WGP. Interest is calculated based on a choice of two methods: a
fluctuating rate equal to the facilitating banks base rate plus an applicable
margin or a periodic fixed rate equal to the London Interbank Offering Rate
(LIBOR) plus an applicable margin. Williams is also required to pay a
commitment fee based on the unused portion of the facility, currently 0.375%.
The applicable margins and commitment fee are based on the relevant borrowers
senior unsecured long-term debt ratings. Current Maturities of Long-term Debt The current maturities of long-term debt at June 30, 2004 are associated
with $200 million of 6 1/8% Notes that mature on January 15, 2005. It is
managements intent to repay the notes from amounts due us through advances to
Williams and refinancing. 4. STOCK-BASED COMPENSATION Employee stock-based awards are accounted for under Accounting Principles
Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees and
related interpretations. Williams fixed-plan common stock options generally do
not result in compensation expense because the exercise price of the stock
options equals the market price of the underlying stock on the date of grant.
The following table illustrates the effect on net income if we had applied the
fair value recognition provisions of Statement of Financial Accounting
Standards (SFAS) No. 123,Accounting for Stock-Based Compensation (in
thousands). 14




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Three Months
    
    Six MonthsEnded June 30,
    
    Ended June 30,2004
    
    2003
    
    2004
    
    2003Net income, as reported
    
    $
    43,332
    
    
    $
    47,851
    
    
    $
    88,680
    
    
    $
    102,784Add/Deduct: Stock-based employee
compensation included
in the Condensed
Consolidated Statement
of Income, net of
related tax effects
    
    
    112
    
    
    
    (55
    )
    
    
    184
    
    
    
    (55
    )Deduct: Stock-based
employee compensation
expense determined
under fair value based
method for all awards,
net of related tax
effects
    
    
    (700
    )
    
    
    (477
    )
    
    
    (1,350
    )
    
    
    (976
    )Pro forma net income
    
    $
    42,744
    
    
    $
    47,319
    
    
    $
    87,514
    
    
    $
    101,753
 Pro forma amounts for 2004 include compensation expense from awards made
in 2004, 2003, 2002 and 2001. Also included in the 2004 pro forma expense is
$0.2 million and $0.4 million of incremental expense for the three and six
months ended June 30, 2004, respectively, associated with the stock option
exchange program discussed below. Pro forma amounts for 2003 include
compensation expense from awards made in 2003, 2002 and 2001. Since compensation expense for stock options is recognized over the future
years vesting period for pro forma disclosure purposes and additional awards
are generally made each year, pro forma amounts may not be representative of
future years amounts. On May 15, 2003, Williams shareholders approved a stock option exchange
program. Under this program, eligible employees were given a one-time
opportunity to exchange certain outstanding options for a proportionately
lesser number of options at an exercise price to be determined at the grant
date of the new options. Surrendered options were cancelled June 26, 2003, and
replacement options were granted on December 29, 2003. We did not recognize any
expense pursuant to the stock option exchange. However, for purposes of pro
forma disclosures, we recognized additional expense related to these new
options and will amortize the remaining expense on the cancelled options
through year-end 2004. 
 ITEM 2. Managements Narrative Analysis of the Results of Operations. Regulatory Matters Order Nos. 2004 and 2004-A (Docket No. RM01-10-000)On November 25, 2003,
the FERC issued Order No. 2004 adopting uniform standards of conduct for
transmission providers. The proposed rules define transmission providers as
interstate natural gas pipelines and public utilities that own, operate or
control electric transmission facilities. The standards regulate the conduct of
transmission providers with their energy affiliates. In Order No. 2004, the
FERC defined energy affiliates broadly to include any non-transmission provider
affiliate that engages in or is involved in transmission (gas or electric)
transactions, manages or controls transmission capacity or that buys, sells,
trades or administers natural gas or electric energy, engages in financial
transactions relating to the sale or transmission of natural gas or
electricity, and Hinshaw and intrastate pipelines. In Order No. 2004-A, issued
on April 16, 2004, the FERC, among other things, clarified the definition of
energy affiliates in a manner which should narrow its scope. Transmission
providers must comply with the new standards of conduct by September 1, 2004.
We filed and posted a plan and schedule for implementing the requirements of
Order No. 2004 on February 9, 2004, and currently are reviewing these new
standards (as modified by Order No. 2004-A), preparing to adopt new compliance
measures and evaluating the impact of increased costs to us. 15




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Since May 1995, Williams Field Services Company (WFS), an affiliated
company, has operated our production area facilities pursuant to the terms of
an operating agreement. In response to FERC Order No. 2004, we terminated the
operating agreement and effective June 1, 2004, we resumed operating these
facilities. We anticipate that the increased costs resulting from the
additional employees required to operate these facilities will be offset by the
discontinuation of the operating fee we were paying to WFS under the terms of
the operating agreement. Williams Recent Events In February 2003, Williams outlined its planned business strategy in
response to the events that significantly impacted the energy sector and
Williams during late 2001 and much of 2002. The plan focused on migrating to an
integrated natural gas business comprised of a strong, but smaller portfolio of
natural gas businesses, reducing debt and increasing Williams liquidity
through assets sales, strategic levels of financing and reductions in operating
costs. The plan was designed to address near-term and medium-term debt and
liquidity issues, to de-leverage Williams with the objective of returning to
investment grade status and to develop a balance sheet and cash flows capable
of supporting and ultimately growing its remaining businesses. As discussed in our Annual Report on Form 10-K for the year ended December
31, 2003, Williams successfully executed certain critical components of its
plan during 2003. Key execution steps for 2004 and beyond include the
completion of planned asset sales, additional reductions of Williams selling,
general and administrative (SG&A) costs, the replacement of its
cash-collateralized letter of credit and revolver facility with facilities that
do not encumber cash and continuation of efforts to exit from the power
business. Asset sales during 2004 were initially expected to generate proceeds
of approximately $800 million. In the first quarter of 2004, Williams
completed an asset sale for proceeds of approximately $304 million. In July
2004, Williams completed the sale of additional assets for approximately $536
million. In addition to these transactions, Williams currently expects to
generate additional proceeds from the sale of assets of approximately $50
million to $100 million. Transco Recent Event On March 17, 2004, the International Brotherhood of Electrical Workers
(IBEW) Local Union 94 filed a petition with the National Labor Relations Board
(NLRB) seeking to represent a single state-wide unit of employees employed at
five facilities within New Jersey. The NLRB declined to find that a single
statewide unit would be appropriate and, instead, found that two district wide
units to include the five locations in New Jersey would be appropriate units.
Elections were conducted by the NLRB on May 26, 2004 at these units to
determine whether the employees would select representation, and a majority of
employees voted to reject representation by the IBEW. General The following discussion should be read in conjunction with the
consolidated financial statements, notes and managements narrative analysis
contained in Items 7 and 8 of our 2003 Annual Report on Form 10-K and in our
2004 First Quarter Report on Form 10-Q and with the condensed consolidated
financial statements and notes contained in this report. 16




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RESULTS OF OPERATIONS Operating Income and Net Income Our operating income for the six months ended June 30, 2004 was $174.9
million compared to operating income of $191.6 million for the six months ended
June 30, 2003. Net income for the six months ended June 30, 2004 was $88.7
million compared to $102.8 million for the six months ended June 30, 2003. The
lower operating income of $16.7 million was primarily the result of lower other
operating revenues and higher administrative and general cost, partially offset
by lower depreciation and amortization expense as discussed below. The decrease
in net income of $14.1 million was attributable to the decreased operating
income and higher net expenses as discussed below in Other Income and Other
Deductions. Transportation Revenues Our operating revenues related to transportation services for the six
months ended June 30, 2004 were $399.4 million, compared to $396.4 million for
the six months ended June 30, 2003. The higher transportation revenues of $3.0
million were primarily due to increased demand revenues of $12.6 million mostly
resulting from new expansion projects (Momentum Phase 1 placed into service on
May 1, 2003, Trenton-Woodbury placed into service on November 1, 2003, and
Momentum Phase 2 placed into service on February 1, 2004), partially offset by
a decrease of $8.5 million of reimbursable costs that are included in operating
expenses and recovered in our rates. As shown in the table below, our total market-area deliveries for the six
months ended June 30, 2004 increased 17.6 trillion British Thermal Units (TBtu)
(2.1%) when compared to the same period in 2003. Increased deliveries were
associated with an increase in power generation relative to the same period in
2003. Our production area deliveries for the six months ended June 30, 2004
increased 23.6 TBtu (17.3%) when compared to the same period in 2003. This is
primarily due to increased deliveries to production area interconnects
resulting from additional offshore supply sources being connected to the
system. Six MonthsEnded June 30,Transco System Deliveries (TBtu)
    
    2004
    
    2003Market-area deliveries:Long-haul transportation
    
    
    402.9
    
    
    
    405.0Market-area transportation
    
    
    433.6
    
    
    
    413.9Total market-area deliveries
    
    
    836.5
    
    
    
    818.9Production-area transportation
    
    
    160.4
    
    
    
    136.8Total system deliveries
    
    
    996.9
    
    
    
    955.7Average Daily Transportation Volumes (Tbtu)
    
    
    5.5
    
    
    
    5.3Average Daily Firm Reserved Capacity (Tbtu)
    
    
    6.7
    
    
    
    6.4
 Our facilities are divided into eight rate zones. Five are located in the
production area and three are located in the market area. Long-haul
transportation is gas that is received in one of the production-area zones and
delivered in a market-area zone. Market-area transportation is gas that is both
received and delivered within market-area zones. Production-area transportation
is gas that is both received and delivered within production-area zones. 17




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Sales Revenues We make jurisdictional merchant gas sales to customers pursuant to a
blanket sales certificate issued by the FERC, with most of those sales being
made through a Firm Sales (FS) program which gives customers the option to
purchase daily quantities of gas from us at market-responsive prices in
exchange for a demand charge payment. Pursuant to the terms of an agreement
with the FERC which resolved an open investigation, we have notified our
merchant sales customers that we will be terminating the merchant sales service
when we are able to do so under the terms of any applicable contracts and FERC
certificates authorizing such services. Under the FS program we must provide
two-year advance notice of termination. Therefore, we notified the FS customers
of our intention to terminate the FS service effective April 1, 2005. Through an agency agreement, WPC manages our jurisdictional merchant gas
sales, excluding our cash out sales in settlement of gas imbalances. The
long-term purchase agreements managed by WPC remain in our name, as do the
corresponding sales of such purchased gas. Therefore, we continue to record
natural gas sales revenues and the related accounts receivable and cost of
natural gas sales and the related accounts payable for the jurisdictional
merchant sales that are managed by WPC. WPC receives all margins associated
with jurisdictional merchant gas sales business and, as our agent, assumes all
market and credit risk associated with our jurisdictional merchant gas sales.
Consequently, our merchant gas sales service has no impact on our operating
income or results of operations and, therefore, the anticipated termination of
such services in April 2005, will have no impact on our operating income or
results of operations. In addition to our merchant gas sales, we also have cash out sales, which
settle gas imbalances with shippers. The cash out sales have no impact on our
operating income or results of operations. Operating revenues related to our sales services were $219.1 million for
the six months ended June 30, 2004, compared to $263.7 million for the same
period in 2003. The decrease was primarily due to a lower volume of merchant
sales during the first six months of 2004 compared to the same period in 2003,
partially offset by higher cash out sales volumes related to the monthly
settlement of imbalances. Six MonthsEnded June 30,Gas Sales Volumes (Tbtu)
    
    2004
    
    2003Long-term sales
    
    
    18.6
    
    
    
    25.9Short-term sales
    
    
    6.3
    
    
    
    11.4Total gas sales
    
    
    24.9
    
    
    
    37.3
 Storage Revenues Our operating revenues related to storage services of $61.8 million for
the six months ended June 30, 2004 were comparable to revenues of $63.0 million
for the same period in 2003. Other Revenues Our other operating revenues were $5.5 million for the six months ended
June 30, 2004 compared to $13.8 million for the same period in 2003. The
reduction was primarily due to a decrease in the sale of environmental
mitigation credits. 18




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Operating Costs and Expenses Excluding the cost of natural gas sales of $217.6 million for the six
months ended June 30, 2004 and $263.7 million for the comparable period in
2003, our operating expenses for the six months ended June 30, 2004, were
approximately $11.7 million higher than the comparable period in 2003. This
increase was primarily attributable to higher cost of natural gas
transportation, operation and maintenance expense, administrative and general
expenses, and taxes other than income taxes, partially offset by lower
depreciation and amortization expense. The higher cost of natural gas
transportation resulted from an increase in fuel expense of $11.0 million due
to the benefit of pricing differentials in 2003 related to volumes of gas used
in operations, partially offset by a decrease of $7.8 million in 2004 of
reimbursable costs that are recovered in our rates. The increase in operation
and maintenance expense in 2004 of $3.3 million is due primarily to increased
materials and supplies cost of $1.4 million and higher maintenance cost of $1.3
million for right-of-way clearing. The increase in administrative and general
expense of $7.4 million is mostly due to increased management services billed
to us by Williams. The higher management services are due primarily to
increased third-party costs associated with the implementation of the
Sarbanes-Oxley Act of 2002 and with efforts at Williams to evaluate and
implement certain cost reduction strategies through internal initiatives and
outsourcing of certain services. The $4.1 million increase in taxes other than
income taxes was mostly due to an increase in franchise taxes in the various
states in which we operate. The lower depreciation and amortization expense of
$7.5 million was due to decreases of $4.9 million associated with lower
environmental mitigation development costs and $4.0 million resulting from an
adjustment to depreciation previously recognized. These decreases were
partially offset by a $1.4 million increase due to the additions in property
resulting from completion of recent construction projects. Other Income and Other Deductions Other income and other deductions for the six months ended June 30, 2004
resulted in higher net expenses of $7.5 million compared to the same period in
2003. This was primarily due to a decrease in the allowance for funds used
during construction resulting from a lower amount of capital projects under
construction. CAPITAL RESOURCES AND LIQUIDITY Method of Financing We fund our capital requirements with cash flows from operating
activities, by repayments of funds advanced to Williams, by accessing capital
markets, and, if required, by borrowings under the Credit Agreement and
advances from Williams. We have an effective registration statement on file with the Securities
and Exchange Commission. At June 30, 2004, $200 million of shelf availability
remains under this registration statement which may be used to issue debt
securities. However, the ability to utilize this registration statement is
currently restricted by certain covenants associated with Williams $800
million 8.625% senior unsecured notes that were issued in 2003. Interest rates,
market conditions, and industry conditions will affect amounts borrowed, if
any, under this arrangement. We believe any additional financing arrangements,
if required, can be obtained from the capital markets on terms that are
commensurate with our current credit ratings. 19




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On May 3, 2004, Williams entered into a new three-year $1 billion secured
revolving credit facility which is available for borrowings and letters of
credit. At June 30, 2004, letters of credit totaling $181 million, none of
which are associated with us, have been issued by the participating
institutions under this facility and no revolving credit loans were
outstanding. Williams also has a commitment from its agent bank to
expand its credit facility by an additional $275 million. Transco and Northwest Pipeline Corporation, a subsidiary of WGP,
have access to $400 million each under the facility. The new facility is
secured by certain Williams midstream assets. Additionally, the facility is
guaranteed by WGP. Interest is calculated based on a choice of two methods: a
fluctuating rate equal to the facilitating banks base rate plus an applicable
margin or a periodic fixed rate equal to LIBOR plus an applicable margin.
Williams is also required to pay a commitment fee based on the unused portion
of the facility, currently 0.375%. The applicable margins and commitment fee
are based on the relevant borrowers senior unsecured long-term debt ratings. As a participant in Williams cash management program, we have advances to
and from Williams. At June 30, 2004, the advances due to us by Williams totaled
$135.5 million. The advances are represented by demand notes. Effective
September 2003, the interest rate on intercompany demand notes is based upon
the weighted average cost of Williams debt outstanding at the end of each
quarter. Previously, the interest rate on intercompany demand notes was based
on the LIBOR plus an applicable margin. Williams has indicated that it
currently believes that it will continue to have the financial resources and
liquidity to repay these advances. Prior to April 29, 2004, the advances flowed
through our parent company, WGP. Credit Ratings The credit ratings on our senior unsecured long-term debt did not change
during the first six months of 2004 and, as of June 30, 2004, are as follows: Moodys Investors Services
    
    
    B1Standard & Poors
    
    
    B+Fitch Ratings
    
    BB
 Capital Expenditures As shown in the table below, our capital expenditures for the six months
ended June 30, 2004 were $68.3 million, compared to $112.0 million for the six
months ended June 30, 2003. Six MonthsEnded June 30,Capital Expenditures
    
    2004
    
    2003(In Millions)Market-area projects
    
    $
    11.1
    
    
    $
    81.0Supply-area projects
    
    
    7.7
    
    
    
    11.0Maintenance of existing facilities and other projects
    
    
    49.5
    
    
    
    20.0Total capital expenditures
    
    $
    68.3
    
    
    $
    112.0
 Our capital expenditures estimate for 2004 and future capital projects are
discussed in our 2003 Annual Report on Form 10-K and 2004 First Quarter Report
on Form 10-Q. The following describes new capital projects proposed by us. Central New Jersey Expansion ProjectThe Central New Jersey Expansion
Project will involve an expansion of our existing natural gas transmission
system in Zone 6 from the Station 210 pooling point 20




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to locations along our Trenton-Woodbury Line. The project will create 105,000
dekatherms per day (dt/d) of new firm transportation capacity, which has been
fully subscribed by one shipper for a twenty-year primary term. The project
facilities will include approximately 3.5 miles of pipeline loop at an
estimated capital cost of $13 million. We plan to file for FERC approval of
the project in the third quarter of 2004. The target in-service date for the
project is November 1, 2005. Leidy to Long Island Expansion ProjectWe held an open season from June
14, 2004 to July 13, 2004 to receive requests for new firm transportation
capacity to be made available from the Leidy Hub in Clinton County,
Pennsylvania to certain Zone 6 delivery points under our proposed Leidy to Long
Island Expansion Project. As a result of the open season, the expansion has
been designed to create 100,000 dt/d of firm transportation capacity, for which
one shipper has submitted a binding commitment for a twenty-year primary term.
The current design of the project facilities includes pipeline looping and
compression facilities and pipeline and compressor upgrades at an estimated
capital cost of approximately $143 million. The final design of the project
facilities is subject to the outcome of our reverse open season solicitation
of permanent capacity release offers. We expect that nearly three-quarters of
the project expenditures will occur in 2007. We plan to file for FERC approval
of the project in the third quarter of 2005. The target in-service date for the
project is November 1, 2007. Other Capital Requirements and Contingencies Our capital requirements and contingencies are discussed in our 2003
Annual Report on Form 10-K. Other than as described in Note 2 of the Notes to
Condensed Consolidated Financial Statements, there have been no new
developments from those described in our 2003 Annual Report on Form 10-K and
2004 First Quarter Report on Form 10-Q with regard to other capital
requirements and contingencies. Conclusion Although no assurances can be given, we currently believe that the
aggregate of cash flows from operating activities, supplemented, when
necessary, by repayments of funds advanced to Williams, advances or capital
contributions from Williams and borrowings under the Credit Agreement will
provide us with sufficient liquidity to meet our capital requirements. When
necessary, we also expect to access public and private markets on terms
commensurate with our current credit ratings to finance our capital
requirements. 
 ITEM 4. Controls and Procedures. An evaluation of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-15(e) and 15(d)-(e)
of the Securities Exchange Act) (Disclosure Controls) was performed as of the
end of the period covered by this report. This evaluation was performed under
the supervision and with the participation of our management, including our
Senior Vice President and Vice President and Treasurer. Based upon that
evaluation, our Senior Vice President and Vice President and Treasurer
concluded that, subject to the limitations noted below, these Disclosure
Controls are effective. Our management, including our Senior Vice President and Vice President and
Treasurer, does not expect that our Disclosure Controls or our internal
controls over financial reporting (Internal Controls) will prevent all errors
and all fraud. A control system, no matter how well conceived and operated, can
provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Further, the design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must
be considered relative to their costs. Because of the inherent limitations in
all control systems, no evaluation 21




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of controls can provide absolute assurance that all control issues and
instances of fraud, if any, within the company have been detected. These
inherent limitations include the realities that judgments in decision-making
can be faulty, and that breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the individual acts of
some persons, by collusion of two or more people, or by management override of
the control. The design of any system of controls also is based in part upon
certain assumptions about the likelihood of future events, and there can be no
assurance that any design will succeed in achieving its stated goals under all
potential future conditions. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur
and not be detected. We monitor our Disclosure Controls and Internal Controls
and make modifications as necessary; our intent in this regard is that the
Disclosure Controls and the Internal Controls will be modified as systems
change and conditions warrant. Notwithstanding the above, management believes that its current controls
are effective. In addition, there has been no material change in our Internal
Controls that occurred during the registrants second fiscal quarter. 22




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PART II  OTHER INFORMATION 
 ITEMS 1. LEGAL PROCEEDINGS. See discussion in Note 2 of the Notes to Condensed Consolidated
Financial Statements included herein. 
 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.  (a)
    
    Exhibits.The following instruments are included as exhibits to
this report. Those exhibits below incorporated by reference
herein are indicated as such by the information supplied in
the parenthetical thereafter. If no parenthetical appears
after an exhibit, copies of the instrument have been included
herewith.  (10)
    
    Material contracts  -
    
    1
    U.S. $1,000,000,000 Credit Agreement
dated as of May 3, 2004, among The Williams Companies,
Inc., Northwest Pipeline Corporation, Transcontinental Gas
Pipe Line Corporation, as Borrowers, Citicorp USA, Inc.,
as Administrative Agent and Collateral Agent, Citibank,
N.A. and Bank of America, N.A., as Issuing Banks, the
banks named therein as Banks, Bank of America, N.A. as
Syndication Agent, JPMorgan Chase Bank, The Bank of Nova
Scotia, The Royal Bank of Scotland plc as Co-Documentation
Agents, Citigroup Global Markets Inc. and Banc of America
Securities LLC as Joint Lead Arrangers and Co-Book Runners
(filed as Exhibit 10.4 to The Williams Companies, Inc.
Form 10-Q for the quarter ended March 31, 2004 Commission
File Number 1-4174).  (31)
    
    Section 302 Certifications  -
    
    1
    Certification of Principal Executive Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the
Securities Exchange Act of 1934, as amended, and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.-
    
    2
    Certification of Principal Financial Officer pursuant to
Rules 13a-14(a) and 15d-14(a) promulgated under the
Securities Exchange Act of 1934, as amended, and Item
601(b)(31) of Regulation S-K, as adopted pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.  (32)
    
    Section 906 Certification  -
    
    1
    Certification of Principal Executive
Officer and Principal Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.  (b)
    
    Reports on Form 8-K.None. 23




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SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized. TRANSCONTINENTAL GAS PIPE LINECORPORATION (Registrant)Dated: August 5, 2004
    
    By /s/ Jeffrey P. HeinrichsJeffrey P. HeinrichsController(Principal Accounting Officer)
 24